Hydraulic fracturing is a common stimulation technique used to enhance production of oil and gas from hydrocarbon containing reservoirs. In a typical hydraulic fracturing operation, fracturing fluid is pumped at high pressures and high rates through a wellbore penetrating a subterranean formation to initiate and propagate hydraulic fractures in the formation. Subsequent steps typically include adding particulate matter known as proppant to the fracturing fluid (e.g., graded sand, ceramic particles, bauxite, or resin coated sand) which is carried by the fracturing fluid into the fractures. The proppant deposits into the fractures, forming a permeable “proppant pack”. Once the fracture treatment is completed, the fracture closes onto the proppant pack allowing for maintenance of the fracture, thereby providing a pathway for hydrocarbons in the formation to flow more easily into the wellbore for recovery.
The use of carbon dioxide (CO2) for production of oil and gas from hydrocarbon containing reservoirs is well known. Utilization of liquid carbon dioxide (LCO2) for the fracture treatment of oil and gas formations has certain advantages in water-sensitive and low pressure formations. In particular, LCO2 enables a significant reduction in the volume of water utilized, and promotes flow-back of water from the formation after fracture treatment. When exposed to aqueous based fluids, formations can trap water for long periods of time, which can result in reduced permeability to hydrocarbons and reduced productivity of the well. Additionally, some clays in the formation can swell in the presence of water or migrate through the formation resulting in closing off or blocking of porosity, again resulting in productivity impairment. Therefore, a reduction in the amount of water introduced into a well can result in decreased formation damage. Moreover, the availability of water for hydraulic fracturing may also be limited in certain geographies of interest for oil and gas production, thereby presenting an economic or regulatory barrier to practical recovery of these resources.
As mentioned above, the fracturing fluid is pumped at high pressures and rates. The pressure generated by the fracturing pumps is known as the “surface treating pressure” and is largely a function of the stress required to create the fracture in the formation, the fracturing fluid frictional pressure losses between the pumps and the formation, and the change in hydrostatic head. The surface treating pressure can be as high as 10,000 psig or more depending on the specific well requirements and pressure capability. The required fracture fluid flow rate is largely a function of the flow required to propagate the fracture and fluid leak-off into the formation. In addition, the flow rate must be sufficient to carry the proppant material (having a tendency to settle out at low flow rates), and is typically in the range 10 to 120 bpm (barrels per minute) depending on the needs of the particular well and fracture design. Well bores commonly can extend from a few thousand feet in shallow vertical wells, to ten or twenty thousand feet or more in long-reach horizontal wells. Common well-bore casing sizes are 4½ inch and 5½ inch, through which the fracturing fluid is pumped. Tubing can also be employed, having a common nominal diameters of 2⅜ inches or 2⅞ inches, inserted through the well casing to carry the fracture fluid. This is performed, for example, when the casing is not strong enough to hold the required fluid pressure.
As can be appreciated there are often scenarios where extremely high frictional pressure drops would be incurred due to high flow rates, small casing or tubing diameters, long well bores, or combinations of these factors. To counteract high pressure drops experienced in conventional fracturing fluids, friction reducers (also commonly referred to as drag reducers) are used. These friction reducers are usually high molecular weight water-soluble polymers, which are directly added and dissolved in the aqueous fracturing fluid, and have been shown to reduce frictional pressure losses by up to about 70%.
The use of “slickwater” fracturing fluids, which employ a friction reducer in a water carrier fluid is well known in the industry. A common friction reducer used in slickwater is a high molecular weight (typically in the range 5,000,000 to 20,000,000 g/mol) polyacrylamide normally supplied as an inverse or water-in-oil emulsion. Concentrations of friction reducers employed in slickwater typically range from about 0.25 gpt (gallons per thousand) to 2 gpt. A key consideration in the design of a friction reducer system is the need to quickly dissolve the friction reducer in the fracturing fluid thereby allowing the friction reducer to become effective as soon as possible, as it is usually only a matter of seconds from the time that the friction reducer is added to when the fracturing fluid first enters the well-bore.
Limited work has been published on the use of high molecular weight polymers as friction reducers for CO2. U.S. Patent Application Publication No. 2012/0037371 A1 to Gupta, et al discloses the use of polychloroprenes, vinyl acetate polymers, polyalkylene oxides and polyalphaolefins as friction reducers in a non-aqueous carrier fluid, which may further include CO2. U.S. Pat. No. 4,573,488 A to Orville et al discloses the use of a homopolymer or copolymer of butylene oxide for friction reduction in non-aqueous carrier fluids. Similarly, U.S. Pat. No. 5,045,220 discloses the use of a polysiloxane and co-solvent for the purposes of thickening CO2, however, this patent states that the polymers used more usually have a molecular weight from 2,000 to 400,000 and that suitable polysiloxanes have a kinematic viscosity of 20,000 centi-Stokes (cSt) to 8,000,000 cSt at 77° F.
The present invention provides for the use of polysiloxanes with a weight average molecular weight of 500,000 g/mol or more and a kinematic viscosity greater than 10,000,000 cSt, at 77° F., in combination with one or more co-solvents, in order to reduce friction in LCO2. It has been found that by employing the fracturing fluid composition of the present invention, one or more of the following objectives can be realized:
CO2 based fracture treatment fluids with reduced frictional loss characteristics can be formed and the friction reducing agents will reduce the pumping equipment and power required to treat a formation and in other cases the friction reducing agents will enable a higher flow rate of fracturing fluid to be used to treat the formation;
additionally, the methods of the present disclosure may provide reduced damage to well formations via the use of non-aqueous fracturing fluids.
Other objects and aspect of the present invention will become apparent to one of ordinary skill in the art upon review of the specification, drawings and claims appended hereto.